In improved oil recovery (IOR) and enhanced oil recovery (EOR) methods, fluids such as water, gas, polymer, surfactant, or combination thereof, are injected into the reservoir through injection wells to maintain reservoir pressure and drive hydrocarbons to adjacent production wells. The success of these recovery processes often depends on their ability to sweep or displace the remaining oil in the reservoir efficiently.
The geology of a reservoir largely impacts the migration or displacement path of hydrocarbons in an IOR or EOR method. In particular, heterogeneity and connectivity in a reservoir greatly impact the route injected fluids travel from an injection well to a production well. For example, the injected fluid generally flows along a low resistance route from the injection well to the production well. Accordingly, the flooding fluid often sweeps through higher permeability geologic regions of the reservoir and bypasses lower permeability geologic regions of the reservoir resulting in a non-uniform displacement of oil. Such higher permeability geologic regions of the reservoir are commonly called thief zones or streaks. Furthermore, fractures, which can be described as open cracks or voids embedded within the rock matrix, may also provide inter-well connectivity. Such connectivity often produces fluid to an intersecting production well at a rate that greatly exceeds the rate of flow through the rock matrix to the well, as the thief zone or fracture typically have a much greater capability to transport fluids.
FIG. 1 shows a schematic illustrating a physical geologic volume of an example reservoir 10 having a plurality of strata 11. The plurality of strata 11 are typically composed of sub-parallel layers of rock and fluid material each characterized by different sedimentological and fluid properties. Reservoir 10 includes strata 13 having a lower permeability and strata 15 having a higher permeability. A portion of lower permeability strata 13 of fractured reservoir 10 is cutaway to illustrate how fractures or fracture networks 17 can further provide connectivity within the reservoir formation or matrix 19 of strata 13,15.
FIG. 2 shows a cross-section of reservoir 10 including injection well 21 and production well 23, which extend to a portion of subsurface reservoir 10 that contains hydrocarbons. In particular, injection well 21 and production well 23 are in fluid communication with strata 13,15 of subsurface reservoir 10. Production well 23 is positioned a predetermined lateral distance away from injection well 21. For example, production well can be positioned between 100 feet to 10,000 feet away from injection well 21. As will be readily appreciated by those skilled in the art, additional injection wells 21 and production wells 23 can extend into reservoir 10 such that multiple production wells 23 optimally receive hydrocarbons being pushed through strata 13,15 due to injections from multiple injection wells 21.
As shown in FIG. 2, fluid 25 injected through injection well 21 tends to sweep through higher permeability strata 15 and does not uniformly sweep the hydrocarbons from lower permeability strata 13 as fluid 25 naturally follows lower resistance paths to production well 23. Furthermore, injection of fluid 25 may result in a phenomenon called fingering or channeling in which injected fluid 25 preferentially follows certain narrow paths 27 through the reservoir formation reservoir matrix 19 to reach production well 23. This non-uniform spreading results in fluid 25 bypassing substantial amounts of hydrocarbons in strata 13,15 of subterranean reservoir 10 such that the bypassed hydrocarbons are not mobilized for recovery. As previously discussed, narrow paths 27 can be due to injection fluids flowing through high permeability thief zones or through fractures to reach production well 23, thus bypassing the majority of reservoir matrix 19 if narrow paths 27 provide inter-well connectivity. In such cases, IOR and EOR processes designed to flow through reservoir matrix 19 can have limited value as fluid cycling can occur through either the fractures or high permeability thief zones.
However, various control methods have been developed to modify the permeability of high permeability thief zones and fractures in a reservoir in efforts to obtain a more uniform sweep, thereby increasing the mobilization and recovery of hydrocarbons. For example, numerous chemical methods commonly referred to as profile or conformance control treatments have been utilized to block, or at least significantly increase the flow resistance of, higher permeability strata. These conformance control treatments also can be used to plug high permeability thief zones or fractures. In particular, polymers or gels are injected into the reservoir that create a low permeability barrier such that flooding fluid thereafter is diverted away from the higher permeability strata, thief zones and fractures. The conformance control material is generally selected based on the properties of the subterranean reservoir such as temperature and salinity.
FIG. 3 shows a cross-section of fractured reservoir 10 where a conformance control treatment has been applied. Chemical slug 29, such as a gel or polymer, has been injected into reservoir 10 through injection well 21. Chemical slug 29 is designed such that it can be injected through the casings and completions of injection well 21, yet does not interfere with operation of injection well 21. Once chemical slug 29 is injected into reservoir 10, it is designed to move through the pores in the reservoir matrix 19 and set at an acceptable distance away from the injection well 21 to create a low permeability barrier within reservoir 10. In some instances, a chase fluid can be utilized to drive chemical slug 29 away from injection well 21 and further into reservoir 10. Once chemical slug 29 sets in reservoir 10 it should have sufficient strength to withstand subsequent flooding fluid injection pressures. Flooding fluid is diverted away from portions of higher permeability strata 15 and narrow paths 27, which are portions of the reservoir that have already been swept. In particular, the injected fluid is now more uniformly distributed in reservoir 10, such as through lower permeability strata 13.
Despite these efforts, many conformance control treatments have shown little or no effect on enhancing hydrocarbon recovery from a reservoir. Such failures may be attributed to the many uncertainties encountered when designing a conformance control application for a particular reservoir. For example, often it is not known where or at what depth to inject chemical slug 29. Additionally, how much chemical to inject in a particular slug is largely a form of guesswork. Finally, there is a lack of control over where chemical slug 29 flows once it enters reservoir 10, and how far away from the injection well 21 chemical slug 29 will set. Accordingly, incorrect or insufficient conformance control designs can result in oil producing zones becoming blocked in addition to the already swept zones. Any improvements in oil productivity might also be transient as the flooding fluid may eventually bypass both the chemical slug barrier and the unswept portions of the reservoir.